1. Field of the Invention
The invention is related generally to the field of interpretation of measurements made by well logging instruments for the purpose of determining the fluid content and permeability of earth formations. More specifically, the invention is related to methods for using Nuclear, Resistivity and Nuclear Magnetic Resonance (NMR) measurements and/or measurements made with a formation testing tool or pressure tests made in laminated reservoirs for determining a distribution of sands, shales and fluids in the reservoir and estimating permeability of the reservoir.
2. Background of the Art
A significant number of hydrocarbon reservoirs include deep water turbidite deposits that consist of thin bedded, laminated sands and shales. A common method for evaluating the hydrocarbon content of reservoirs is the use of resistivity measurements. In interpretation techniques known in the art, typically one or more types of porosity-related measurement will be combined with measurements of the electrical resistivity (or its inverse, electrical conductivity) of the earth formations to infer the fluid content within the pore spaces of the earth formations. The fractional volumes of connate water and hydrocarbons can be inferred from empirical relationships of formation resistivity Rt with respect to porosity and connate water resistivity such as, for example, the well known Archie relationship. In the Archie relationship fractional volume of water in the pore space is represented, as shown in the following expression, by Swxe2x80x94known as xe2x80x9cwater saturationxe2x80x9d:                               S          w          n                =                                            R              0                                      R              t                                =                                    1                              R                t                                      ⁢                                          aR                w                                            φ                m                                                                        (        1        )            
where a and m are empirically determined factors which relate the porosity (represented by "PHgr") to the resistivity of the porous rock formation when it is completely water-saturated (R0), Rw represents the resistivity of the connate water disposed in the pore spaces of the formation, and m represents an empirically determined xe2x80x9ccementationxe2x80x9d exponent, n is the saturation exponent.
Relationships such as the Archie formula shown in equation (1) do not work very well when the particular earth formation being analyzed includes some amount of extremely fine-grained, clay mineral-based components known in the art as xe2x80x9cshalexe2x80x9d. Shale typically occurs, among other ways, in earth formations as xe2x80x9cdispersedxe2x80x9d shale, where particles of clay minerals occupy some of the pore spaces in the hydrocarbon-bearing earth formations, or as laminations (layers) of clay mineral-based rock interleaved with layers of reservoir-type rock in a particular earth formation.
In the case of dispersed shale, various empirically derived relationships have been developed to calculate the fractional volume of pore space which is capable of containing movable (producible) hydrocarbons. The fractional volume of such formations which is occupied by dispersed shale can be estimated using such well logging devices as natural gamma ray radiation detectors. See for example, M. H. Waxman et al, xe2x80x9cElectrical Conductivities in Oil Bearing Shaly Sandsxe2x80x9d, SPE Journal, vol. 8, no. 2, Society of Petroleum Engineers, Richardson, Tex. (1968).
In the case of laminated shale, the layers sometimes are thick enough to be within the vertical resolution of, and therefore are determinable by, well logging instruments such as a natural gamma ray detector. In these cases, the shale layers are determined not to be reservoir rock formation and are generally ignored for purposes of determining hydrocarbon content of the particular earth formation. A problem in laminated shale reservoirs is where the shale laminations are not thick enough to be fully determined using gamma ray detectors and are not thick enough to have their electrical resistivity accurately determined by electrical resistivity measuring devices known in the art.
Sands that have high hydrocarbon saturation are typically more resistive than shales. In reservoirs consisting of thin laminations of sands and shales, conventional induction logging tools greatly underestimate the resistivity of the reservoir: the currents induced in the formation by the logging tool flow preferentially through the conductive shale laminations creating a bias towards a higher formation conductivity. This could lead to an underestimation of hydrocarbon reserves.
One method for estimating hydrocarbon content of earth formations where shale laminations are present was developed by Poupon. See A. Poupon et al, xe2x80x9cA Contribution to Electrical Log Interpretation in Shaly Sandsxe2x80x9d, Transactions AIME, Vol. 201, pp. 138-145 (1959). Generally the Poupon relationship assumes that the shale layers affect the overall electrical conductivity of the earth formation being analyzed in proportion to the fractional volume of the shale layers within the particular earth formation being analyzed. The fractional volume is typically represented by Vsh (shale xe2x80x9cvolumexe2x80x9d). Poupon""s model also assumes that the electrical conductivity measured by the well logging instrument will include proportional effects of the shale layers, leaving the remainder of the measured electrical conductivity as originating in the xe2x80x9ccleanxe2x80x9d (non-shale bearing) reservoir rock layers as shown in the following expression:                               1                      R            t                          =                                            (                              1                -                                  V                  sh                                            )                        ⁢                                          (                                                      aR                    w                                                        φ                    m                                                  )                                            -                1                                      ⁢                          S              w              n                                +                                    V              sh                                      R              sh                                                          (        2        )            
where Rt represents the electrical resistivity (inverse of conductivity) in the reservoir rock layers of the formation and Rsh represents the resistivity in the shale layers.
The analysis by Poupon overlooks the effect of anisotropy in the resistivity of a reservoir including thinly laminated sands and shales. Use of improper evaluation models in many cases may result in an underestimation of reservoir producibility and hydrocarbon reserves by 40% or more as noted by van den Berg and Sandor. Analysis of well logging instrument measurements for determining the fluid content of possible hydrocarbon reservoirs includes calculating the fractional volume of pore space (xe2x80x9cporosityxe2x80x9d) and calculating the fractional volumes within the pore spaces of both hydrocarbons and connate water. As noted above, Archie""s relationship may be used.
In thinly laminated reservoirs where the wavelength of the interrogating electromagnetic wave is greater than the thickness of the individual layers, the reservoir exhibits an anisotropy in the resistivity. This anisotropy may be detected by using a logging tool that has, in addition to the usual transmitter coil and receiver coil aligned along with the axis of the borehole, a receiver or a transmitter coil aligned at an angle to the borehole axis. Such devices have been well described in the past for dip determination. See, for example, U.S. Pat. No. 3,510,757 to Huston and U.S. Pat. No. 5,115,198 to Gianzero.
Co-pending U.S. patent application Ser. No. 09/474,049 (the ""049 application) filed on Dec. 28, 1999 and the contents of which are fully incorporated herein by reference, disclosed a method of accounting for the distribution of shale in a reservoir including laminated shaly sands using vertical and horizontal conductivities derived from multi-component induction data. Data such as from a borehole resistivity imaging tool give measurements of the dip angle of the reservoir, and the resistivity and thickness of the layers on a fine scale. The measurements made by the borehole resistivity imaging tool are calibrated with the data from the induction logging tool that gives measurements having a lower resolution than the borehole resistivity imaging tool. A tensor petrophysical model determines the laminar shale volume and laminar sand conductivity from vertical and horizontal conductivities derived from the log data. The volume of dispersed shale and the total and effective porosities of the laminar sand fraction are determined using a Thomas-Stieber-Juhasz approach. Removal of laminar shale conductivity and porosity effects reduces the laminated shaly sand problem to a single dispersed shaly sand model to which the Waxman-Smits equation can be applied.
Co-pending U.S. patent application Ser. No. 09/539,053 (the ""053 application) filed on Mar. 30, 2000, having the same assignee as the present application, and the contents of which are fully incorporated herein by reference, discloses a method of accounting for the distribution of shale and water in a reservoir including laminated shaly sands using vertical and horizontal conductivities derived from multi-component induction data. Along with an induction logging tool, data may also be acquired using a borehole resistivity imaging tool. The data from the borehole resistivity imaging tool give measurements of the dip angle of the reservoir, and the resistivity and thickness of the layers on a fine scale. The measurements made by the borehole resistivity imaging tool are calibrated with the data from the induction logging tool that gives measurements having a lower resolution than the borehole resistivity imaging tool. The measurements made by the borehole resistivity imaging tool can be used to give an estimate of Vsh-LAM, the volume fraction of laminar shale. A tensor petrophysical model determines the laminar shale volume and laminar sand conductivity from vertical and horizontal conductivities derived from the log data. The volume of dispersed shale, the total and effective porosities of the laminar sand fraction as well as the effects of clay-bound water in the formation are determined.
The method of the ""053 application is not readily applicable to reservoirs in which the sands may be intrinsically anisotropic without making additional assumptions about the sand properties. Sands in turbidite deposits commonly comprise thin laminae having different grains size and/or sorting: the individual laminae may be isotropic but on a macroscopic scale relevant to logging applications, the laminations exhibit transverse isotropy. In addition, a reservoir including turbiditic sands exhibits an anisotropic permeability. Being able to determine this anisotropic permeability is important from the standpoint of reservoir development. This is an issue not addressed in the ""053 application and of considerable importance in development of hydrocarbon reservoirs.
In one aspect of the invention, a method of petrophysical evaluation of a formation is disclosed wherein horizontal and vertical resistivities of the formation are inverted using a tensor petrophysical model to give a first estimate of fractional volume of laminated shale in the formation. This first estimate of fractional volume of laminated shale is comparted to a second estimate obtained from measurements of density and/or neutron porosity of the formation using a volumetric model. If the second estimate of fractional shale volume is greater than the first estimate of fractional shale volume, the horizontal and vertical resistivities are inverted using a tensor petrophysical model including the second estimate of fractional shale volume and obtaining a vertical and horizontal resistivity of an anisotropic sand component of the formation. This vertical and horizontal resistivity of the anisotropic sand component is used in conjunction with at least one additional measurement selected from the group consisting of: of (i) NMR measurements of the formation, and, (ii) a bulk permeability of the sand component to obtain properties a coarse and a fine grain portion of the sand component. The obtained properties of the coarse and fine grain portions of the sand include water saturations, and resistivities.
The properties of the coarse and fine grain portions of the sand are derived using an iterative solution process wherein a out of a family of possible distributions of said properties, a selection is made that matches the NMR measurement or the bulk permeability measurement. Relationships such as the Timur Coates equation may be used for the purpose. The bulk permeability measurement may be obtained from a formation testing instrument, a pressure build up test, a pressure drawdown test or from an NMR diffusion measurement.
Measurements of the horizontal and vertical resistivity may be obtained using a transverse induction logging tool, or from a conventional induction logging tool and a focused current resistivity tool.